US green hydrogen production costs, excluding the production tax credit (PTC), could fall from $3–6/kg today to $1.5–2/kg by 2035, according to a recent Department of Energy (DoE) report. The PTC awards a maximum of $3/kg based on lifecycle carbon intensity over a period of ten years for low-carbon hydrogen production projects that begin construction before 2033.

While the predicted green hydrogen price by the mid-2030s is higher than the ‘Hydrogen Shot’ target, which aims for low-carbon hydrogen production to cost $1/kg by 2031, “depending on type of electrolyser and availability of high-capacity factor clean energy, some projects may hit the Hydrogen Shot target”, the DoE says.

The department expects electrolyser capex to more than halve for both proton-exchange-membrane (PEM) and alkaline electrolysers, while low-carbon electricity at under $20/MWh will be increasingly available by the end of the decade.

$3/kg – Maximum PTC for low-carbon hydrogen

However, it also notes that electrolyser manufacturing capacity will have to scale up, given wait times for delivery are quoted at 2–3 years. This could present a potential challenge depending on which electrolyser technologies take off, as PEM electrolyser demand in the US alone could require 15–30pc of global iridium raw material production—80pc of which is produced in South Africa with almost no opportunity for domestic production. The DoE notes the US has sufficient resources and supply chains in place for other key raw materials, such as stainless steel, titanium, zirconium and nickel.

Blue hydrogen—produced using methane with carbon capture—is expected to reach $1.2/kg by 2030 from $1.6/kg today. The DoE also anticipates that the lowest carbon intensity boundary of blue hydrogen would qualify it only for $0.75/kg of the PTC. However, blue hydrogen producers have the option of taking advantage of either the PTC or the 45Q $85/t tax credit for CCS. “Because the value of the hydrogen PTC scales with lifecycle emissions of produced hydrogen while the 45Q credit does not, the 45Q credit may be more attractive for projects with higher upstream methane emissions and higher pre-capture carbon intensity,” the DoE notes.

Hydrogen produced purely using grid-powered electrolysis is expected to be prohibitively expensive—at $4.2/kg today and $3.4/kg by 2030—and ineligible for the PTC owing to the current carbon intensity of the US grid.

Around 10.5mn t/yr of the 12mn t/yr announced low-carbon hydrogen production capacity has still not taken FID.

The DoE expects that, by 2025, costs of low-carbon hydrogen production with the PTC applied will be below what end-users are willing to pay—assuming production cost savings are passed to consumers.

Down the value chain

The DoE notes that midstream infrastructure and downstream switching will both require significant investment over the coming decades. Around $85–215bn of investment will be required to scale the domestic hydrogen economy by 2030—half of which will be needed for midstream and end-use infrastructure and a third of which will be required for the necessarily scale-up in low-carbon electricity.

As of the end of last year, more than $15bn of planned investment was estimated for announced production projects that had reached the feasibility study stage, whereas only $6bn was estimated for all announced midstream and downstream infrastructure. While the pipeline of announced production projects would cover expected 2030 demand if all secured financing, announced projects cover only 5pc of distribution and storage infrastructure and 25pc of end-use requirements by that year.

Midstream

Midstream and downstream infrastructure is also expected to need a significant ramp-up in investment from 2030. The DoE anticipates that sectors that already use hydrogen at scale, such as refining and agrichemicals, will act as anchor offtakers in the near term—although it also notes that current ammonia producers may largely opt to decarbonise via CCS rather than switching feedstock and reformation processes. However, from 2030, more sectors that can switch to using hydrogen and its derivatives—such as steelmaking, maritime and aviation fuels and power—will require capital investment towards adopting new technology. The DoE estimates that investment will need to rise to $15–20bn/yr for midstream and $10–15bn/yr for end-use switching between 2030 and 2050.

Midstream options include freight transport as a compressed gas or liquid, construction of dedicated pipelines or blending into existing gas connections. Dedicated hydrogen pipelines have the lowest levelised cost for volumes over 50t/d over long distances but require permitting approval and high upfront capex of $2–10mn/inch-mile for 6–14-inch diameter pipes. While the DoE raises blending as an option—noting that the technical threshold for existing gas-run appliances could be as high as 15pc, as is the case in the state of Hawaii—it also notes that more research is needed and separation costs could be prohibitively expensive.

For storage infrastructure, the DoE leans toward salt caverns as the lowest levelised cost option, at $0.05–0.15/kg by 2030. However, it notes that, as these structures are also used to store other gases, there is likely to be competition for limited space.

Export potential

The US “could emerge as a net exporter of hydrogen and hydrogen derivatives if it can move quickly to capitalise on its natural advantages”, the DoE says, noting that trade body the Hydrogen Council estimates the country could export 20mn t/yr of hydrogen in 2050, half as methanol to Asia. However, the DoE notes that regulations by importers will likely limit supply to green hydrogen, while hydrogen will have to be liquefied or transported as ammonia over long distances—both options with major inefficiencies.

The DoE notes that existing ammonia infrastructure could be used to export the chemical to countries that lack natural gas resources, CCS sites or abundant renewable resources, such as Japan and South Korea. However, the US is likely to face competition with low-carbon ammonia producers in regions with high renewables capacity, low construction costs and fewer constraints around permitting and project siting, such as in the Middle East, the DoE cautions.

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Author: Polly Martin